Integrated system for investigating sub-surface features of a rock formation

ABSTRACT

A system for investigating non-linear properties of a rock formation around a borehole is provided. The system includes a first sub-system configured to perform data acquisition, control and recording of data; a second subsystem in communication with the first sub-system and configured to perform non-linearity and velocity preliminary imaging; a third subsystem in communication with the first subsystem and configured to emit controlled acoustic broadcasts and receive acoustic energy; a fourth subsystem in communication with the first subsystem and the third subsystem and configured to generate a source signal directed towards the rock formation; and a fifth subsystem in communication with the third subsystem and the fourth subsystem and configured to perform detection of signals representative of the non-linear properties of the rock formation.

GOVERNMENT RIGHTS

This invention was made with Government support under CooperativeResearch and Development Agreement (CRADA) Contract NumberDE-AC52-06NA25396 awarded by the United States Department of Energy. TheGovernment may have certain rights in this invention.

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. patent application Ser. No.61/413,173, filed on Nov. 12, 2010, the entire contents of which isincorporated herein by reference.

FIELD

The present invention relates generally to seismic interrogation of rockformations and more particularly to creating three-dimensional images ofnon-linear properties and/or the compressional to shear velocity ratioin a region remote from a borehole using a combination of sources in aborehole, and receiving and analyzing a resultant third wave formed by amixing process.

BACKGROUND

Acoustic interrogation of subsurface features tends to be limited by thesize and power of practical sources, and in practice, the output of downhole acoustic transducers is limited by the power transmissioncapabilities of the wireline cable. High frequency signals have arelatively short penetration distance, while low frequency signalsgenerally require large sources, clamped to the borehole wall, tomaximize energy transfer to the formation and minimize unwanted signalswithin the well bore. Currently, acoustic borehole tools are designedwith acoustic sources in the borehole to detect returning acoustic wavesthat are propagating along the borehole walls or scattered byinhomogeneities of linear properties of rock formations surrounding theborehole. U.S. Pat. No. 7,301,852 to Leggett, III et al. discloses aLogging While Drilling tool, designed to detect rock formationboundaries. The tool uses two acoustic source arrays emitting twoacoustic waves from a borehole that generate a third wave by non-linearmixing in the rock formation surrounding the borehole at the location ofintersection of the acoustic waves. The third wave continues forward andinteracts linearly with heterogeneities in the subsurface properties.The third wave is scattered by the heterogeneities in the subsurfaceproperties, and the scattered signal is detected by sensors in thelogging tool. U.S. Pat. No. 7,301,852 does not discuss detecting thethird wave directly but rather the signal that is scattered by theheterogeneities in the rock formation. U.S. Pat. No. 7,301,852 merelyuses the resultant scattered wave to detect rock formation boundaries.

Attempts have been made to characterize the non-linear properties of aformation in the area of oil and gas prospecting from boreholes, buteach has its own limitations. For example, U.S. Pat. No. 5,521,882 toD'Angelo et al. discloses an acoustic tool designed to record withpressure receivers non-linear waves generated by non-linear mixing oftwo waves. The non-linear waves propagate along the borehole wall withlimited penetration into the surrounding rock formation and refract backinto the well bore fluid. The indication of non-linearity is utilized toprovide an indication of the relative consolidation of the formationsurrounding the borehole. U.S. Pat. No. 5,521,882 does not discussmeasuring non-linear characteristics of a rock formation away from theborehole. U.S. Pat. No. 6,175,536 by Khan discloses a method to estimatethe degree of non-linearity of earth formations from spectral analysisof seismic signals transmitted into the earth formations from a firstborehole and received in a second borehole. The method in U.S. Pat. No.6,175,536 determines from the spectral analysis the presence of afrequency at a receiver located at the second borehole representing asum or a difference of two selected frequencies of the transmittedseismic signals generated by two sources located at the first borehole.U.S. Pat. No. 6,175,536 does not discuss measuring non-linearcharacteristics of a rock formation in a remote region of a boreholewhere the receiver and the sources are located in one borehole.

In light of these prior attempts, there is a need for a system andmethod for characterizing non-linear properties in a remote region froma borehole.

SUMMARY

An aspect of the present disclosure is to provide a system forinvestigating non-linear properties of a rock formation around aborehole. The system includes a first sub-system configured to performdata acquisition, control and recording of data; a second subsystem incommunication with the first sub-system and configured to performnon-linearity and velocity preliminary imaging; a third subsystem incommunication with the first subsystem and configured to emit controlledacoustic broadcasts and receive acoustic energy; a fourth subsystem incommunication with the first subsystem and the third subsystem andconfigured to generate a source signal directed towards the rockformation; and a fifth subsystem in communication with the thirdsubsystem and the fourth subsystem and configured to perform detectionof signals representative of the non-linear properties of the rockformation.

These and other objects, features, and characteristics of the presentinvention, as well as the methods of operation and functions of therelated elements of structure and the combination of parts and economiesof manufacture, will become more apparent upon consideration of thefollowing description and the appended claims with reference to theaccompanying drawings, all of which form a part of this specification,wherein like reference numerals designate corresponding parts in thevarious Figures. It is to be expressly understood, however, that thedrawings are for the purpose of illustration and description only andare not intended as a definition of the limits of the invention. As usedin the specification and in the claims, the singular form of “a”, “an”,and “the” include plural referents unless the context clearly dictatesotherwise.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a configuration for creating three-dimensional images ofnon-linear properties in a region remote from a borehole, in accordancewith various aspects of the disclosure;

FIG. 2 shows another configuration for creating three-dimensional imagesof non-linear properties in a region remote from a borehole, inaccordance with aspects of the disclosure;

FIG. 3 shows yet another configuration for creating three-dimensionalimages of non-linear properties in a region remote from a borehole, inaccordance with aspects of the disclosure;

FIG. 4 shows a flow chart for creating three-dimensional images ofnon-linear properties in a region remote from a borehole, in accordancewith various aspects of the disclosure;

FIGS. 5 a, 5 b and 5 c shows a numerical simulation of the firstselection rule for a beam-beam interaction listed in Table 1 when thetwo primary waves are beams;

FIG. 6 illustrates the geometry of the generation of the differencefrequency third wave by non-linear mixing of two primary acoustic wavesas governed by the non-linear mixing selection rule;

FIG. 7 shows an application of aspects of the present disclosure forimaging using a beam and broad beam or plane wave;

FIG. 8 shows an example configuration for a borehole-based system forremote mapping of non-linear properties and/or Vp/Vs ratio of rockformations using non-collinear acoustic mixing, in accordance with anaspect of the present disclosure;

FIG. 9 a shows the configuration of FIG. 8 for the purposes ofidentifying vectors representing the broadcast and scattered acousticwaves;

FIG. 9 b shows a vector representation of the non-collinear acousticmixing of FIG. 9 a;

FIG. 10 a shows a representative dependence of mixing coefficient on theplane wave frequency ratio for a range of mixing zone compressionalvelocity and shear velocity ratios Vp/Vs, in accordance with aspects ofthe present disclosure;

FIG. 10 b shows a representative dependence of convergence angles withplane wave frequency ratio that honor the selection rules for the P+P

SV interaction;

FIG. 10 c shows a representative dependence of scattering angles withplane wave frequency ratio that honor the selection rules for the P+P

SV interaction;

FIGS. 11 a to 11 c show example results of a numerical simulation ofnon-collinear interaction of plane waves in a non-linear medium leadingto the generation of a scattered wave that returns to the borehole, inaccordance with aspects of the present disclosure;

FIG. 12 a shows an example representation of the directions and thetimes of flight for the primary and scattered acoustic waves inaccordance with aspects of the present disclosure;

FIGS. 12 b-12 d show an example of a simulated signal from a firstacoustic source, a simulated signal from second acoustic source, and asimulated template signal, according to an embodiment of the presentdisclosure;

FIG. 13 a shows a position of a first acoustic source and a secondacoustic source and a receiver array, according to an embodiment of thepresent disclosure;

FIGS. 13 b to 13 d show how correlation of the received series of pulseswith a modeled template signal results in identification of the signal'sarrival time at the receiver array, in accordance with an embodiment ofthe present disclosure;

FIG. 14 a shows a position of a first acoustic source and a secondacoustic source and a receiver array, according to an embodiment of thepresent disclosure;

FIGS. 14 b to 14 d show the effect of transmitting a series of codedpulses and using correlation techniques to improve signal to noiseratio, in accordance with aspects of the invention;

FIGS. 15 a and 15 b show an example non-collinear mixing arrangement ina toroid around the borehole at intersection of two coaxial cones, inaccordance with aspects of the present disclosure;

FIGS. 16 a and 16 b show an example non-collinear mixing arrangementbetween two intersecting coaxial cones, in accordance with aspects ofthe present disclosure;

FIG. 17 a shows an example single well arrangement with a crankedrathole where there is a complete intersection of lower cone with uppercone, in accordance with aspects of the present disclosure;

FIG. 17 b shows another example single well arrangement with a crankedrathole where a lower transmitter emits energy near perpendicular to aborehole axis, in accordance with aspects of the present disclosure;

FIG. 18 a shows an example of a vertical well and sidetrack withreceivers in the vertical part of the well, in accordance with aspectsof the present disclosure;

FIG. 18 b shows another example of a vertical pilot hole and horizontalsidetrack with receivers in the sidetrack, in accordance with aspects ofthe present disclosure; and

FIG. 19 is a schematic system diagram of a system for performing surveydesign, data acquisition, data processing and imaging, in accordancewith aspects of the present disclosure.

DETAILED DESCRIPTION

FIG. 1 shows one of several possible configurations for creatingthree-dimensional images of non-linear properties and the compressionalto shear velocity ratio in a region remote from a borehole in accordancewith various aspects of the disclosure. First acoustic source 105 isarranged in borehole 110 to generate a steerable primary beam ofacoustic energy at a first frequency f₁. Second acoustic source 115 isalso arranged in borehole 110 to generate a steerable primary beam ofacoustic energy at a second frequency f₂. By way of a non-limitingexample, both first acoustic source 105 and second acoustic source 115may be a phased array of sources and may be configured to generateeither compressional or shear steerable beams. In the presentdisclosure, the term “acoustic” can refer to P, SV or SH acoustic mode.

As shown in FIG. 1, first acoustic source 105 is arranged on first toolbody 120 and second acoustic source 115 is arranged on second tool body125. However, the disclosure is not so limiting as first tool body 120and second tool body 125 may also be arranged together on a common toolbody (not shown). Tool bodies 120 and 125 are arranged to beindependently moveable within bore hole 110 in at least two degrees offreedom including translation along the longitudinal axis 150 ofborehole 110 and rotation 155 in azimuth about the longitudinal axis ofborehole 110. First acoustic source 105 may be arranged above or belowsecond acoustic source 115 in borehole 110. Tool bodies 120 and 125 maybe arranged on a conveyed logging tool (not shown) within borehole 110.

For a given azimuth orientation of first acoustic source 105 and secondacoustic source 115, the beam generated by second acoustic source 115and the beam generated by first acoustic source 105 are configured suchthat the beams converge and intercept in mixing zones 130 remote fromborehole 110. By a combination of independently steering the beams andchanging the separation between the sources 105, 115, the mixing zones130 move in a plane defined by the beams and the longitudinal boreholeaxis 150, while controlling the angle of interception. The distance ofmixing zones 130 from borehole 110 can range from near the edge ofborehole 110 to about 300 meters into the surrounding subsurface rockformation. By way of a non-limiting example, the phase difference and/orstart time differences between adjacent elements in the source array105, 115 referred to in the above paragraphs may be modified to focusthe acoustic energy of the primary beams at a particular mixing zone130.

The non-linear properties of the earth at the location between the twowaves result in the generation of a third elastic wave. The thirdelastic wave is a result of a three-wave mixing process that occurs innonlinear materials, in this case, rock formations. In this process, twoconverging non-collinear waves of different frequencies, f₁ and f₂, alsocalled primary waves, mix to form additional waves at the harmonic andintermodulation frequencies f₁−f₂, f₁+f₂, 2×f₁ and 2×f₂, etc. Thestrength of the third wave is a function the non-linearity of the rocksin the mixing zones. By way of a non-limiting example, when a primarycompressional (P) wave with a frequency f₁ and a primary shear (SV) wavewith a frequency f₂ cross or intersect in a non-linear medium, a thirdcompressional (P) or shear (SV) wave is generated with a frequencyf₁−f₂.

Under propagation selection rules, the third wave propagation vector isco-planar with the propagation vectors of the two primary waves. Certaincombinations of angle of intersection, f₁/f₂ ratio and compressional toshear velocity ratio result in a third elastic wave with frequency f₁−f₂propagating in a specific angle relative to the primary beams back tothe borehole 110.

Sensor or receiver array 135 is arranged at a specific location inborehole 110 to detect the third wave returning to the borehole 110. Inone embodiment, as shown for example in the FIG. 1, sensor array 135comprises more than one sensor, arranged as an array of sensors onsensor tool body 140 and separate from tool bodies 120 and 125. Sensor135 is configured to be independently moveable within bore hole 110along the longitudinal axis 150 of borehole 110. For example, sensortool body 140 can be arranged below tool bodies 120 and 125 or arrangedabove and below tool bodies 120 and 125. In some embodiments, sensortool body 140 can be connected to either or both tool bodies 120 and125.

The third wave is detected at borehole 110 by sensor array 135. FIG. 2shows an arrangement similar to FIG. 1, wherein receiver 135 includesthree component geophone 145 clamped to the borehole walls. Theresultant signal is decomposed by processing into its elevation andazimuth in order to add redundancy to the system by determining thedirection of the incoming third wave arrival.

In one embodiment, a first processor or controller can be provided andconfigured to execute machine-readable instructions (not shown) toperform various processing tasks, such as controlling source firing andcompressing or filtering the data recorded by sensor array 135. In oneembodiment, the first processor can be arranged within the borehole 110.In one embodiment, a second processor can be provided and configured toexecute machine-readable instructions (not shown) to assist the firstprocessor or perform different processing tasks than the firstprocessor. For example, the second processor may perform part or allprocessing activities in creating the three-dimensional images. Atransmitter or transceiver (not shown) may be arranged in borehole 110to transmit data up-hole through a wireline cable (not shown). In oneembodiment, the second processor can be, for example, arranged outsidethe borehole.

At a given depth along the borehole of one of the sources 105, 115,sweeping the beams in elevation at constant relative bearing tospatially scan the mixing zone in a plane passing through the boreholeaxis, rotating the sources azimuthally to rotationally scan the mixingregion and moving the whole assembly along borehole 110, results inscanning a 3D volume of mixing zones around the borehole for non-linearproperties. With sources 105, 115 and sensor array 135 located onindependent tool bodies, redundancy in the data can be obtained and thedepth of investigation can be varied. In this way, a 3D volume of therocks surrounding the borehole can be interrogated for non-linearproperties and a 3D image of non-linear properties can be processed andcomputed from the returned signals, i.e., signals detected by sensorarray 135.

FIG. 3 shows another arrangement for creating three-dimensional imagesof non-linear properties in a region remote from borehole 110 inaccordance with another embodiment of the present invention. Thearrangement of FIG. 3 is similar to the arrangement in FIG. 2, with theprimary difference being that the sources are arranged in borehole 110to produce elastic waves (e.g., spherical waves) instead of steerabledirectional beams. With reference to FIG. 3, first acoustic source 305is arranged in borehole 110 on first tool body 320 to generate a firstelastic wave of acoustic energy at a first frequency f₁. Second acousticsource 315 is arranged in borehole 110 on second tool body 325 togenerate a second elastic wave of acoustic energy at a second frequencyf₂. First and second elastic waves produced by sources 305, 315 arearranged to intersect away from borehole 110 at various mixing zones130. Receiver 145 is arranged within borehole 110 to receive a thirdwave that is produced in the mixing zones 130 by the three-wave mixingprocess discussed above, and further discussed below. Since the wavesproduced by sources 305, 315 are essentially non-directional, mixingbetween the waves occurs simultaneously in the entire area of mixingzones 130, that also extends out of the plane of the Figure, andreceiver 145 tends to have directional characteristics. By way of anon-limiting example, a three component geophone array may be used forthis purpose. The resultant signal is decomposed by processing intomultiple arrival signals at a range of elevations and azimuths andtravel times. Given the locations of sources 305 and 315 and thereceivers 145, the travel times and directions of each decomposeddirectional arrival, there is sufficient information to apply selectionrules described in the following paragraphs to determine a unique mixingzone where the third wave was generated. This unique mapping allows theconstruction of a three dimensional (3D) image from the properties ofthe received signal.

FIG. 4 shows a flow chart for a method of creating three-dimensionalimages of non-linear properties and the compressional to shear velocityratio in a region remote from a borehole using a conveyed logging tool,according to an embodiment of the present invention. The method beginsat 405 where a first acoustic source is arranged in the borehole togenerate a steerable beam elastic energy at a first frequency and asecond acoustic source is arranged in the borehole to generate asteerable beam of elastic energy at a second frequency. The steerablebeams at the first and second frequency are arranged to intersect at alocation away from the borehole. As such, the second beam is generatedat the same azimuth as the first beam, but at a different elevationrelative to the longitudinal axis of the borehole. The method continuesat 410 where a third elastic wave is received at the borehole by asensor array. As discussed above, the third elastic wave is created by amixing process, with a frequency equal to a difference between the firstand second frequencies and a direction of propagation towards theborehole. At 415, a mixing location away from the borehole is determinedfrom the arrangement of the first and second acoustic sources andproperties of the third wave, by recourse to the selection rules. At420, three-dimensional images are created of the non-linear propertiesusing data recorded by repeating the generating of step 405, thereceiving of step 410 and the determining of step 415 at a plurality ofazimuths, elevations and longitudinal locations within the borehole. Incases of compressional-shear interaction, the received signals areanalyzed in step 425 for the compressional/shear velocity (Vp/Vs) ratioas discussed in the above paragraphs. At 430, the non-linear propertiesare transformed to physical reservoir properties such as fluidsaturation, effective stress, fracture density and mineralogy.

In some aspects of the present disclosure, the first and second acousticsources may be beam or cylindrical, or spherical wave sources, and thesensor array may be any combination of non-directional single componentsensors and three component geophones. Alternative permutations of thecomponent parts offer different degrees of redundancy in signalprocessing and imaging.

In the special case where a primary compressional (P) wave with afrequency f₁ and a primary shear (S) wave with a frequency f₂ cross eachother, in a non-linear medium, a third P or S wave is generated with thefrequency f₁−f₂. If the primary P and S waves are beams with wavevectors k₁ and k₂, respectively, and the non-linear formation propertyis uniform, the kinematics of wave interaction requires the resultingthird wave to be a plane wave with wave vector k₃ that obeys theselection rule k₁−k₂=k₃. The selection rule imposes a very tightrestriction on the permissible crossing angles for the primary waves anda specific propagation direction of the third wave. The generalkinematic theory for non-linear mixing of two linear plane waves and theselection rules and amplitude responses have contributions from Jonesand Kobett (1963), Rollins, Taylor et al. (1964) and later by Korneev,Nihei and Myer (1998), all of which are hereby incorporated by referencein their entirety, who also provide specific relationships betweennon-linear parameters of the mixing medium and the non-linear mixingsignal strength. For example, Equation 53 and 54 of Korneev, Nihei andMyer show that the mixing strength of P and SV (vertically polarizedshear) plane waves is proportional to a specific combination ofnon-linear parameters of the rocks.

The selection rules governing the nonlinear interaction of two elasticplane waves can be used as guidance for the interaction of two elasticbeams. These plane wave selection rules dictate that the following sixnonlinear interactions produce backscattered waves.

TABLE 1 Selection Rules Governing Non-Linear Interaction of Two ElasticPlane Waves. In this table, and elsewhere in this document, f₁ isgreater than f₂. Selection 1^(st) beam 2^(nd) beam Resultant 3^(rd) beamor Rules or wave or wave wave from 1^(st) + 2^(nd) 1 P(f₁) SV(f₂) P(f₁ −f₂) 2 P(f₁) SV(f₂) SV(f₁ − f₂) 3 P(f₁) SH(f₂) SH(f₁ − f₂) 4 P(f₁) SV(f₂)P(f₁ + f₂) 5 SV(f₁) SV(f₂) P(f₁ + f₂) 6 SH(f₁) SH(f₂) P(f₁ + f₂)

FIGS. 5 a, 5 b and 5 c shows a numerical simulation of selection rule 1of Table 1 when the two primary waves are beams of a beam-beaminteraction. A 25 kHz compressional beam, shown in FIG. 5 a, and a 18kHz shear beam, shown in FIG. 5 b, mix to form a third beam, shown inFIG. 5 c, with frequency 7 kHz=25 kHz−18 kHz. In this example, inaccordance with the plane wave predictions, a third back propagating Pbeam with frequency (f₁−f₂) at an angle of 133° to the P(f₁) wave isgenerated by nonlinear mixing in the region where the P(f₁) and SV(f₂)beams overlap.

The kinematics of non-linear interactions of beams results in thegeneration of specific combinations of wave vectors and frequencies. Thethird wave returns at a specific travel time, and with specificfrequencies f₃ and wave vectors k₃ such as f₃=f₁−f₂ and k₃=k₁−k₂. For acombination of f₁, f₂, k₁ and k₂, there is a well-defined propagationwave vector k₃ of the third wave in the same plane, defined by k₁ andk₂. There is a direct correspondence between the signal detected at aparticular receiver position and the location where the non-linearmixing of the two primary waves k₁ and k₂ takes place. The signalstrength of the receiver would be proportional to the strength of thenon-linearity of the rocks in the mixing zone, among other factors, andreach a maximum for a receiver lying on vector k₃. Therefore, the signalstrength at the receivers can be geometrically mapped onto thenon-linearity of the rocks along the beam trajectory as shown, forexample, in FIG. 1.

The geometrical theory of wave propagation indicates that the beamgenerated in each mixing zone would arrive at the borehole at a specificreceiver defined by the geometry of the three wave vectors k₁, k₂ andk₃, after a specific time delay. The strength of the returning signal ata specific location in the borehole at a particular time is dependent onthe degree of non-linearity of the interaction location. Hence, a timeimage of the relative strength of the non-linear properties of the rocksalong the beam can be constructed. The amplitude or magnitude of areturned signal at the receivers can be itself indicative of certainpetrophysical properties of the mixing zone. If the beam and plane waveare scanned in azimuth and elevation while preserving the convergenceangle, a localized circumferential and radial 3D image of non-linearproperties of rocks surrounding the borehole can be obtained. By movingthe entire assembly up and down the borehole, repeated 3D images ofnon-linear properties of rocks surrounding the borehole can be obtained.By making weighted stacks of these repeated images, a final image ofnon-linear properties of rocks surrounding the entire borehole can beconstructed through subsequent computer processing. In addition, if thesources and the receivers are part of three separate tool bodies, one ortwo can be moved while the third one is fixed (for example, the sourcesare fixed while the receiver tool body is moved up and down).Alternatively, several descents into the well may be made with differentspacing between the tool bodies.

For non-linear mixing between an elastic beam and a broader beam (quasiplane wave), the selection rule is relaxed. Third waves of frequencyf₁−f₂, centered around the wave vector k₃=k₁−k₂, are generatedcontinuously along the primary beam if the beam width is about tenwavelengths of the third wave. The resulting signal strength forf₃=f₁−f₂ is a function of the average non-linear properties of themixing region, the average ratio of velocity of f₁ propagation andaverage velocity for f₂ propagation (noting that beams with frequenciesf₁ and f₂ may be compressional or shear), the volume of the mixing zoneand the geometry of the mixing. This function can be computed forvarious mixing modes. For example, the signal strength for a particularmixing mode such as compressional wave P for f₁ and SV for f₂ is givenby

$\begin{matrix}{U = {2\pi^{2}\beta_{{PS}_{v}P}A_{1}B_{2}\frac{f_{1}{f_{2}\left( {f_{1} - f_{2}} \right)}}{V_{P}^{2}V_{s}}\frac{V_{{PS}_{v}P}}{L}F_{PSvP}\Delta_{{PS}_{v}P}}} & (1)\end{matrix}$where U is the displacement amplitude of the third wave received at theborehole, A₁ is the longitudinal polarization of the compressional waveand B₂ is the transverse polarization of the shear wave. β is a functionof the A, B and C parameters of Landau and Lifschitz representing thenon-linearity of the rocks in the mixing zone. v is the volume of themixing zone, L is the distance from mixing zone to the receiver. F isthe geometric form factor of order 1 which is dependent on the geometryof the incident beams and can be numerically computed for the particulargeometry. Δ is a selection rule form factor which is a numericallycomputable function of the wave vectors k₁, k₂ and k₃ and is onlysignificant if the interaction geometry honors the selection rules. Thesubscript PS_(V)P in the formula refers to compressional-shearinteraction generating a compressional wave.

In accordance with certain aspects of this disclosure, an image of thecompressional to shear velocity ratio may be constructed as follows.When one of the sources generates a compressional wave (P-wave) withfrequency f₁ and the other source generates an SV-wave with frequency f₂and both waves are steered towards a specific intersection volume, thepropagation direction of the third compressional wave (P-wave) withdifference frequency f₃=f₁−f₂ is controlled by the average in situ Vp/Vsvelocity ratio of the rock in the mixing zone as governed by theselection rules as shown in FIG. 6. From the measurements of the signalin the three component receiver array 145 on FIG. 2 or FIG. 3, thedirection of this third wave can be determined and thereby, the in situVp/Vs of the mixing zone can be computed. If the beam and plane wave arescanned in azimuth and elevation while preserving the necessaryconvergence angle, a localized circumferential and radial 3D image of insitu Vp/Vs ratio of rocks surrounding the borehole can be obtained. Bymoving the entire assembly up and down the borehole, repeated 3D imagesof in situ Vp/Vs of rocks surrounding the borehole may be obtained. Bymaking weighted stack of these repeated images, a final image of in situVp/Vs of rocks surrounding the entire borehole can be constructedthrough subsequent computer processing. Alternatively, several descentsinto the well may be made with different fixed spacing between the toolbodies.

In some aspects of this disclosure, an alternative determination ofVp/Vs ratio is achieved through scanning the ratio of the frequencies f₁to f₂ of the primary beams. FIG. 6 illustrates the geometry of theinteraction of two beams such as those generated in the configuration ofFIG. 1, that may be analyzed using the vector mathematics andtrigonometry. The lengths k₁ and k₂ of vectors k₁ and k₂ are defined bythe ratio of their corresponding frequencies and velocities. As shown inFIG. 6, the returning angle φ is a function of f₁/f₂, Vp/Vs ratio andthe intersection angle θ of the two primary beams. In addition, thephysical selection rules only permit the generation of a third wave atspecific combinations of f₁/f₂, Vp/Vs ratio and angle of interception θ,such as the example illustrated on FIG. 5.

Using the symbol r for the Vp/Vs ratio and the terms defined on FIG. 6,the magnitude k₃ of vector k₃ is given by the vector sum of k₁ and −k₂,that is

$k_{3} = {{{k_{1} - k_{2}}} = \frac{f_{1} - f_{2}}{V_{p}}}$and also by the cosine rule that states k₃ ²=k₁ ²+k₂ ²−2k₁k₂ cos θ.Combining the two equations, and substituting f₁/Vp for k₁ and f₂/Vs fork₂, leads to a statement of the geometric conditions imposed by theselection rules. The quadratic equation

${{\frac{f_{2}}{f_{1}}r^{2}} - {2r\;\cos\;\theta} - \frac{f_{2}}{f_{1}} + 2} = 0$may be solved for r, the Vp/Vs ratio of the mixing zone. This leads to anon-limiting alternative method for measuring in situ Vp/Vs ratio of aparticular mixing region by the following sequence: a) record a standardsonic waveform log to determine Vp and Vs near the borehole to acquiredata to estimate the phase differences between adjacent elements in aphased source array to steer the beams at the approximate convergenceangle for the geometry of the planned measurement; b) steer the P and SVsources to converge at a controlled angle θ and mix at a particularregion in space surrounding the borehole; c) vary f₂ while fixing f₁ andmeasure the amplitude of the received signal at the difference frequencyf₁−f₂ at the sensors in the borehole; d) identify the frequency at whichthe signal each receiver in the array reaches a maximum amplitudestrength; and e) determine angles θ and φ from the geometry of thesources and receivers. By sweeping the beams in elevation, rotating inazimuth, and moving the entire assembly up and down the borehole andrepeating the above procedure, the Vp/Vs ratio of a 3D volume around theborehole is interrogated and thereby 3D images of in situ Vp/Vs ratio ofrocks surrounding the borehole may be obtained.

The methods described above provide that the frequency difference f₁−f₂is very specific, allowing for spectral analysis to enhance the signalto noise ratio of the measurements. Moreover, if both frequencies f₁ andf₂ are simultaneously chirped proportionally, the resulting differencefrequency signal f₁−f₂ would also be a well defined chirped signal. Thetime-varying code may include one or more of a variation in amplitude, avariation in frequency, and/or a variation in phase of the first, thesecond, or both the first and the second beams or waves. The thirddifference wave can be broadband if one of the primary frequencies isswept through a range of frequencies while their frequency ratio isfixed. Thus, the resulting third beam f₂−f₁ will be swept across a widefrequency range, while preserving the same direction. This allows forimprovement in signal to noise by standard auto-correlation of thechirped or coded signal.

Since the wave vector k₃=k₁−k₂ is well defined, the signal to noisediscrimination of the recorded third wave from receivers 135 can beenhanced further by employing three-component receivers in the borehole.For example, the signals from the three components can be tuned tospecific directivity by a technique, such as, hodogram analysis.

In some aspects of the present disclosure, the signal to noise ratio canbe improved by repeating the above steps and using an inverse polarity(180 degrees out of phase) source signals and adding the resultstogether. The returning difference frequency signal will add coherentlyas its amplitude is proportional to the product of the amplitudes of thetwo primary waves and therefore will not reverse polarity when thepolarity of the primary source is reversed. On the other hand, anylinear noise generated by the primary sources in the system will reversepolarity and thus cancel upon addition.

Alternative methods can be devised with various non-exclusivecombinations of beams and waves. By way of a non-limiting example, amethod to generate images by computer processing of acoustic and seismicsignals includes the following steps. First, the method performsspectral analysis of the frequency content of the recorded third waveand applicable selection rules of the difference frequency signal inorder to isolate the third wave signal generated by the non-linearmixing process. In the case that the sensors include three componentgeophones, determine the direction of the third wave impinging on theborehole using orientation techniques. The method continues by analyzingthe amplitude of the recorded third wave as a function of frequencyratios of the primary mixing waves and determining the mixing locationwhere the third wave signals originated, from the selection rules ofnon-collinear mixing in non-linear media, the wavenumbers of the firstand second beams and the third wave and the locations of the two beamsources and the sensor array. The method continues by constructingseismograms determined by cross-correlation of the received signals withchirped transmitter signals for each source-receiver combination. Themethod continues by performing three dimensional time or depth imagingto the entire data set, in order to obtain three dimensional images ofthe non-linear properties of the formation surrounding a borehole ineither or both of time and distance. The methods for generating imagesfrom seismograms are known, for example, Hill et al., which is herebyincorporated by reference, have provided the general methodology for thespecial case of imaging from beams.

Another non-limiting alternative imaging method is illustrated in FIG.7, which shows the case of interactions of a narrow 705 and a broad(wide) beam 710. Given a smooth background model of Vp and Vs of theinvestigated volume, application of the selection rules enables thegeometric mapping of the energy detected at a receiver location 735 onto mixing zones 730 along the narrow beam. A time image of thenon-linear property can thus be constructed along the narrow beam. Byrotating in azimuth and moving the assembly along the borehole, a threedimensional time image can be constructed of a volume centered on theborehole. Successive repetition of the measurement at different beamelevations, and altering the f₂/f₁ frequency ratio yields a series ofthree dimensional time images. This redundancy in imaging permitsfurther refinement of the smooth background model and a threedimensional spatial image.

Non-linear parameters of rocks have been found to be related to a numberof important hydrocarbon reservoir parameters, such as variations withgas, oil and water saturation, effective stress, fracture density andmineralogical content. In certain aspects of this disclosure, the 3Dimages of non-linear properties constructed by the above method aretransformed to provide quantitative information on the distribution ofthese properties around the borehole at the time of recording. Inaddition, sequential repetitions of this method are used to detectchanges in reservoir properties over time for reservoir monitoringpurposes.

The recordings of received waveforms are processed to generate an imageof the non-linear characteristics of the formation. The directivity ofthe beam and the time of flight may fix the locations where scatteredwaves are generated, thus, distinguishing this method from normal sonicimaging techniques using conventional non-directional monopole anddipole sources.

By way of a non-limiting example, when a primary compressional (P) wavewith a frequency f₁ and a primary compressional (P) wave with afrequency f₂ cross in a non-linear medium, and the selection rules arehonored, a third shear (SV) wave can be generated with a frequencyf₁−f₂. This particular configuration can be used for creating 3D imagesof the Vp/Vs velocity ratio and non-linear properties of the rockformations around the borehole for many ranges of distance ofinvestigation from a borehole. This particular example of compressionalnon-linear mixing to generate a shear wave (i.e., P+P→SV) will be usedto describe a number of new concepts, methodologies, processes andsystems for measurement and analysis purposes in the followingparagraphs. These are equally applicable to P+SV→SV or any permutationof non-linear mixing of two acoustic compressional or shear waves togenerate a third wave.

FIG. 8 shows an example configuration for a borehole-based system forremote mapping of non-linear properties and Vp/Vs velocity ratio of rockformations using non-collinear acoustic mixing in accordance with anaspect of the present disclosure. Two primary acoustic beams, forexample compressional (P) waves, from upper and lower arrays oftransmitters 801 and 802 located in borehole 800, are directed into therock formation surrounding the borehole. The transmitter arrays can beoriented such that acoustic energy propagates at any azimuth φ₁ 809 andφ₂ 811 and elevation α₁ 810 and α₂ 812 relative to the borehole axis.For suitable elevation angles α₁, α₂, and azimuth angles φ₁ and φ₂, thetwo primary P beams propagating through the rock formation intersectwith convergence angle θ 804 at an mixing zone 805, remote from borehole800. The convergence angle θ is defined as the angle between thedirections of the two converging beams, represented on FIG. 8 as thelines joining the two transmitters 801 and 802 to the mixing zone 805.If the rock formation at the point of intersection has non-linearproperties, a secondary (S) shear wave SV (e.g., a shear wave polarizedin the plane defined by the axes of the two intersecting compressionalwaves) is generated due to non-linear interaction. The secondary shearwave propagates in a direction defined by the selection rules,represented by scattering angle, ψ, 806. The scattering angle ψ, isdefined as the angle between the axis of the acoustic wave from thelower transmitter and the axis of the scattered wave. In theconfiguration shown, energy 807 returns to the borehole and is recordedat receiver or array of receivers 803.

As discussed above, the conditions suitable for generation of asecondary shear wave can be inferred from the selection rules that canbe derived by the conservation of energy and conservation of momentum.The secondary wave S must obey either of the following conditionsf ₃ =f ₁ −f ₂  (2)k ₃ =k ₁ −k ₂  (3)orf ₃ =f ₁ +f ₂  (4)k ₃ =k ₁ +k ₂  (5)

where k₁, k₂ and k₃ are wave vectors. The first frequency condition,where f₃=f₁−f₂, is of particular interest for investigating propertiesof rock formation near a borehole. As shown in FIG. 9, the conditions(2) and (3) can be represented by the formation of the wave-vectortriangles and satisfied by the following relationships (6), (7) and (8).|k ₃|=2π|f ₁ −f ₂ |/Vs=(|f ₁ −f ₂ |/Vp)×(Vp/Vs)  (6)|k ₁|=2πf ₁ /Vp  (7)|k ₂|=2πf ₂ /Vp  (8)

Using trigonometry in the vector diagram of FIG. 9 b, it can be shownthat these conditions can be met when equations (9) and (10) assatisfied.

$\begin{matrix}{{\sin\left( {\theta/2} \right)} = {\left( {1 - \frac{f_{2}}{f_{1}}} \right)\frac{\sqrt{\left( {{Vp}/{Vs}} \right)^{2} - 1}}{2\sqrt{\frac{f_{2}}{f_{1}}}}}} & (9) \\{{\sin(\psi)} = {\left( {f_{2}/f_{1}} \right) \times \;{{\sin(\theta)}/\left( {1 - {f_{2}/f_{1}}} \right)}}} & (10)\end{matrix}$

Since the Vp/Vs velocity ratio is in the range 1.5 to 3.0 for manysedimentary rocks, there are combinations of convergence angle θ andfrequency ratio f1/f2 (denoted herein as d) that permit the generationof a secondary shear wave SV that propagates back to the borehole in theconfiguration shown in FIG. 9 a.

As discussed above, the behavior of acoustic energy generated bynon-linear interaction of intersecting non-collinear planar waves can becalculated. The selection rules define a set of permitted interactions.The P+P→SV interaction is additional to the partial listing on Table 1.These various interactions use certain combinations of convergenceangle, frequency ratio and scattering angle that depend on whether theconverging waves are compressional or shear, on the Vp/Vs velocity ratioof the material at the interaction location, and differ for interactionsgenerating sum (f₁+f₂) and difference (f₁−f₂) frequency energy. Thegeometry presented in the following examples is based on the P(f₁)+P(f₂)

SV(f₁−f₂) interaction, and analogs could equally be presented for otherpermitted interactions generating difference or sum frequency resonance,for example, but not limited to, interactions including P(f₁)+SV(f₂)

SV(f₁−f₂) and P(f₁)+SV(f₂)

P(f₁−f₂).

For example, considering P(f₁)+P(f₂)

SV(f₁−f₂), FIG. 10 a shows mixing coefficient W as a function of thefrequency ratio of the two sources. The mixing coefficient W, which is ameasure of the amplitude of the efficiency of the conversion generatingthe scattered wave, is given by equation (11).

$\begin{matrix}{W = {D\frac{\left( {1 + {f_{1}/f_{2}}} \right)}{2\left( {{Vs}/{Vp}} \right)}{\sin\left( {2\;\theta} \right)} \times m}} & (11)\end{matrix}$where D depends on the Lamé coefficients λ and μ and is proportional tof₂/f₁ for a given mixing zone, as defined in equation (12).

$\begin{matrix}{D = \frac{f_{1}/f_{2}}{4{\pi\left( {\lambda + {2\mu}} \right)}}} & (12)\end{matrix}$θ is the convergence angle of the two primary beams at the mixing zone,and m is a scaling factor related to the Landau-Lifshitz non-linearconstants A and B, as expressed in equation (13),

$\begin{matrix}{m = {\frac{A}{2} + B}} & (13)\end{matrix}$Hence, m is constant for a given mixing zone.

FIGS. 10 a, 10 b and 10 c show the dependence of mixing coefficient W,convergence angle and scattering angle on Vp/Vs velocity ratio in therange from 1.5 to 2.0 at the mixing location, assuming a representativevalue (from Korneev, Nihei and Myer 1998) for m of −3660 GPa. FIG. 10 ashows the dependence of mixing coefficient on the plane wave frequencyratio for a range of mixing zone Vp/Vs ratios. FIGS. 10 b and 10 c showthe corresponding convergence and scattering angles that honor theselection rules for the P+P

SV interaction. As can be understood from FIG. 10 a, the mixingcoefficient reaches a maximum at a ratio of the second frequency f2 tothe first frequency f1 equal to about 0.7. In addition, from FIG. 10 b,it can be appreciated that when the ratio of the second frequency f2 tothe first frequency f1 is equal to about 0.7, the convergence angle isin the range between about 30 deg. and about 40 deg. Moreover, it canalso be appreciated that when the ratio of the second frequency f2 tothe first frequency f1 is equal to about 0.7, a scattering angle of thereturning wave relative to a direction the first wave is equal to about40 deg.

FIGS. 11 a to 11 c show example results of numerical simulations ofnon-collinear interaction of acoustic beams in a non-linear mediumleading to the generation of a scattered wave that returns to theborehole. In FIGS. 11 a to 11 c, borehole 1100 includes lowertransmitter 1101, upper transmitter 1102 and receiver array 1103.Acoustic energy in the form of a compressional beam generated by lowertransmitter 1101 and upper transmitter 1102 converges at a distance fromborehole at convergence angle 1104. Receiver array 1103 is arranged toreceive scattered wave 1107 which is produced by the interaction of theacoustic beams as defined by the selection rules, described above andagain below, at scattering angle 1106. In FIGS. 11 a, 11 b and 11 c,distance along the borehole in meters is shown versus radial distanceaway from borehole in meters. In FIGS. 11 a and b, the volumetricstrains associated with the compressional acoustic energy of the twobeams produced by the two sources are shown. In FIG. 11 c, the shearstrain associated with the scattered shear wave 1107 is shown.

In the following paragraphs a coded scheme that can be used to enhanceor extract measured scattered acoustic waves that originate fromnon-linear mixing of primary acoustic signals in a mixing zone within arock formation around the borehole is described. Measurements ofscattered acoustic waves generated from non-linear acoustic phenomena inrock formations away from the borehole can be enhanced by broadcastingcoded primary acoustic signals, recording the returning signal from thenon-linear interaction and subsequently using a waveform recognitionmethod and/or a band pass filtering method based on the forecastproperties of the non-linear signal. One non-limiting example is tocorrelate the recorded signal with a template representing a forecast ofits timing and frequency content derived from the broadcast parametersin accordance with the selection rules. The result of this correlationrepresents an acoustic pulse traveling past the borehole. For example,in the case of the P+P→SV interaction, the returning energy resultingfrom the non-linear interaction appears to travel along the borehole ata velocity equal to the shear wave velocity of the formation divided bythe cosine of the angle between its propagation direction and theborehole axis. When applied to a system such as that illustrated in FIG.8, the coding and correlation method improves the detection of the weaknon-linear signal and thereby enhances the construction of 3D images ofnon-linear properties and Vp/Vs velocity ratio in the volume probed bythe measurement

One non-limiting implementation for utilizing coding and signalcorrelation for the enhancement of signals generated by non-collinearacoustic mixing in a non-linear medium is described in the followingparagraphs. A detailed description of a more general implementation ofthe coding scheme can be found in U.S. patent application Ser. No.13/292,948 entitled “System and Method for Generating Micro-SeismicEvents and Characterizing Properties of a Medium With Non-LinearAcoustic Interactions,”, filed concurrently with the presentapplication, the entire contents of which is incorporated herein byreference. Referring to FIGS. 12 a through 12 d, source 1201 starts tobroadcast a first coded or modulated time train u₁(t), consisting of asequence of N acoustic pulses, at time t=0. The nth acoustic pulse hasfrequency f_(n) and an amplitude envelope E1 _(n)(t−T_(n)) of limitedtime duration, where n=1,2 . . . N and T_(n) is the broadcast time ofthe nth pulse. The time separation between sequential pulses isvariable. In some embodiments, the time separation between sequentialpulses is much longer than the time duration of the individual pulsesand the pulses do not overlap. A second coded or modulated time train,u₂(t), is broadcast from source 1202. This second coded or modulatedtime train consists of a sequence of N sequential acoustic pulses andstarts at time t=δ, where δ is a start time difference between a starttime of a broadcast of the first coded train and a start time of abroadcast of the second coded train. In one embodiment, the start timedifference can be understood as a time delay between the broadcast ofthe first coded train and the second coded train. As it can beappreciated, the broadcast of the first coded train can be delayedrelative to the broadcast of the second coded train or vice versa. Inthe present description it is often referred to δ as being a “timedelay”. However, δ should be interpreted broadly to be a “timedifference” as the second pulse sequence may start before the first. Thenth acoustic pulse has frequency d*f_(n) and an amplitude envelope E2_(n)(t−(T_(n)+δ)) of limited time duration, where n=1,2 . . . N. Thefrequency ratio between corresponding pulses in the two trains is fixedat d. T_(n)+δ is the broadcast time of the nth pulse. The amplitudeenvelopes E1 and E2 of the first and second coded signal trains,respectively, can be different or the same. Examples of the time codedsignal trains are shown in FIGS. 12 b-12 c. These coded signals can berepresented mathematically by following formulas (14) and (15). In thepresent description the symbol “*” is used for as a multiplicationoperator.

$\begin{matrix}{\mspace{79mu}{{u_{1}(t)} = {\sum\limits_{n}{E\; 1_{n}\left( {t - T_{n}} \right)*{\exp\left( {{\mathbb{i}}\; 2\pi*f_{n}*\left( {t - T_{n}} \right)} \right)}*{\exp\left( {{\mathbb{i}}\;\zeta_{n}} \right)}}}}} & (14) \\{{u_{2}\left( {t - \delta} \right)} = {\sum\limits_{n}{E\; 2_{n}\left( {t - \left( {T_{n} + \delta} \right)} \right)*{\exp\left( {{\mathbb{i}}\; 2\pi*d*f_{n}*\left( {t - \left( {T_{n} + \delta} \right)} \right)} \right)}*{\exp\left( {{\mathbb{i}}\;\zeta_{n}} \right)}}}} & (15)\end{matrix}$where ζ_(n) is a phase of each pulse n and exp(iζ_(n)) is a phase termof each pulse n.

The respective signal envelopes E1 _(n)(t−Tn) and E2 _(n)(t−(Tn+d)) canhave any shape or form such as a Gaussian form, etc. Similarly, althoughthe modulated signals within the envelopes are expressed in equations(14) and (15), they can be modeled by other mathematical formulas. Whenthe time delay δ is equal to the difference in travel times t1 and t2(that is to say δ=t1−t2) from transmitters 1201 and 1202 to the mixingzone 1204, the acoustic energy of corresponding pulses n from the twobroadcast trains arrives simultaneously at the mixing zone and, if theconvergence angle, frequency ratio and Vp/Vs ratio at the mixinglocation are accord with the selection rules' criteria, generates athird series of scattered acoustic pulses with dominant frequency(1−d)*f_(n), equal to the difference between the frequencies in the twoprimary pulses, f_(n) and d*f_(n). This third wave, denoted u₃, recordedat the receiver, inherits the coding of the two primary signals andtherefore may be expressed as equation (16).

$\begin{matrix}{{u_{3}(t)} \propto {\sum\limits_{n}{E\; 3_{n}\left( {t - \left( {T_{n} + T} \right)} \right)*{\exp\left( {{\mathbb{i}}\; 2\pi*\left( {1 - d} \right)*f_{n}*\left( {t - \left( {T_{n} + T} \right)} \right)} \right)}*{\exp\left( {{\mathbb{i}}\;\zeta_{n}} \right)}}}} & (16)\end{matrix}$where ζ_(n) is a phase of each pulse n and exp(iζ_(n)) is a phase termof each pulse n of the third wave.

E3 _(n)(t) is the resulting amplitude envelope due the mixing of theprimary pulses and T is the total travel time from the source 1 to therecording receiver via the center of the mixing zone as furtherexplained below.

In one embodiment, signal enhancement can be accomplished using acorrelation technique well known in seismic processing industry toextract a relevant part of the non-linear interaction and travel timeinformation in measured signal u₃. The technique involves theconstruction of a template signal u_(S) that has the coded signal formas expressed in equation (17).

$\begin{matrix}{{u_{s}(t)} = {\sum\limits_{n}{{W_{n}\left( {t - T_{n}} \right)}*{\exp\left( {{\mathbb{i}}\; 2\pi*{g\left( f_{n} \right)}*\left( {t - T_{n}} \right)} \right)}*{\exp\left( {{\mathbb{i}}\;\zeta_{n}} \right)}}}} & (17)\end{matrix}$where ζ_(n) is a phase of each pulse n and exp(iζ_(n)) is a phase termof each pulse n of the template signal.W_(n) is some suitably chosen envelope function and g(f_(n)) is somesuitably chosen function of frequency f_(n). The selection of anappropriate function g(f_(n)) may be based on the shape of the expectedmodulated signal within the measured signal u₃ to achieve the bestnon-linear signal extraction. For example, g(f_(n)) can be selected tobe (1−d)*f_(n) such that u_(s) is equal to

${u_{s}(t)} = {\sum\limits_{n}{{W_{n}\left( {t - T_{n}} \right)}{\exp\left( {{\mathbb{i}}\; 2{\pi\left( {1 - d} \right)}\left( {t - T_{n}} \right)} \right)}{\exp\left( {{\mathbb{i}}\;\zeta_{n}} \right)}}}$as shown in FIG. 12 d. However, other functions g(f_(n)) are also withinthe scope of the present invention.

To extract the signals from non-linear interactions in u₃, across-correlation between u₃ and u_(s) can be performed to obtain thecorrelated signal M where M is mathematically defined by equation (18).M(t)=∫u ₃(t′)*u _(s)(t−t′)dt′  (18)

It can be shown mathematically that the resulting correlated signal M isa sharp band-limited spike with a bandwidth including all thefrequencies (1−d)*fn for n=1,2, . . . , N when the number of pulses N islarge. The term “band-limited” spike is used herein to refer to a spikesignal having a limited frequency bandwidth. In one embodiment,increasing the broadcast duration by increasing the number of pulses Nenhances signals generated by non-linear interaction in the correlatedsignal M while more effectively suppressing signals generated by linearinteractions and other noise. It should be noted that the correlationtechnique using the coded signal pattern is one of many ways to extractand enhance signals generated by non-linear interactions. Alternativesignal processing techniques including pattern recognition or frequencyband filtering could equally be used for signal extraction andenhancement.

The correlated measured signal M has the following properties. First,the correlated signal contains a sharp band-limited spike, correspondingto the non-linear interaction at the mixing zone, only if the time delayδ between first and second primary coded signals is equal to thedifference between the travel time t₁ from the first acoustic source1201 to the mixing zone 1204 and the travel time t₂ from the secondacoustic source 1202 to mixing zone 1204, i.e. δ=t₁−t₂. If thiscondition is not met, the correlated signal is highly suppressed.Second, if the condition δ=t₁−t₂ is met, the band-limited spike occurson the correlated signal M(t) at the time T which is equal to a sum ofthe travel time from the first primary acoustic source to the mixingzone and the travel time from the mixing zone 1204 to the receiverwithin the receiver array 1203, i.e. T=t₁+t₃=δ+t₂+t₃. Third, increasingthe duration of the coded signal train, i.e., increasing the number ofpulses N in the broadcast train, improves discrimination of signal fromnoise_(e), because the noise does not have the form of the templatesignal u_(s).

Numerical simulation results of a case where the lower transmitter 1201and upper transmitter 1202 emit two coded signal trains consisting ofsequential acoustic pulses with Gaussian envelopes are shown in FIG. 13a-13 d. In this non-limiting example, coded signals of 12 pulses areused with frequency pairs (574 Hz, 373 Hz) (624 Hz, 405.6 Hz) (700Hz,455 Hz) (757 Hz,492 Hz) (802 Hz, 521.3 Hz) (870.5 Hz,566 Hz) (947 Hz,615.5 Hz) (1000 Hz,650 Hz) (1120 Hz, 728 Hz) (1218 Hz, 792 Hz) (1324 Hz,861 Hz) (1440 Hz,936 Hz). The frequency ratio f₂/f₁ between the pairs isa constant 0.65. The start time delay δ between the two signal trains ischosen to be equal to (t1−t2). Numerical simulation of the non-linearinteraction due to the broadcast of the two coded wave trains u₁ and u₂is performed on a computer. The simulated signals due to non-linearinteraction from a broadcast of two sequential pulses received andrecorded at six of 110 receivers, indexed from 1 to 110, in thenon-limiting example of a receiver array 1203 are shown in FIG. 13( b).The template u_(s) for the returning coded signal is shown in FIG. 13(c). The result of correlation between the template signal with therecorded signal at each receiver is shown in FIG. 13( d). The resultingcorrelated signal at each receiver shown in FIG. 13( d) shows a verysharp band-limited spike. This sharp spike occurs at the time T=t1+t3where t1 is the travel time from the source 1 to the center of themixing zone and t3 is the travel time from the center of the mixing zoneto the receiver. The time delays or “move-out” across the receiver arrayare as though the acoustic energy is traveling along the borehole withan apparent velocity equal to the shear wave velocity divided by thecosine of the angle between the direction of the returning wave and theborehole axis.

The numerical simulation shown in FIGS. 13 a-13 d clearly illustratesthe power and utility of the coding scheme when used in conjunction withthe system of measurement in FIGS. 12 a-12 d or FIG. 8. It allows forcomputer processing of the recorded signals at the receivers to generatecorrelated records that contain band-limited spike signals with strengthproportional to the strength of the non-linear interaction at the mixingzone 1204. The arrival time T of the band-limited spike is equal to thetotal travel time from source 1201 to mixing zone 1204 and back to theborehole at receiver 1203. The amplitude of the band-limited spikes varywith the receiver position with a maximum occurring at a particularreceiver, the location of which is dependent on the scattering angle ψ1206 of the non-linear interaction at mixing zone 1204. The scatteringangle ψ is dependent on the properties of the rocks, e.g. Vp/Vs velocityratio, at the mixing zone 1204. It should be noted that this result is acharacteristic of the coding scheme and of the measurement system shownin FIG. 12 a-12 d or FIG. 8. The use of Gaussian envelopes and codedsignals in conjunction with templates are non-limiting examples used forthe purpose of illustrating the coding scheme and its characteristics.Variants of u₁,u₂ and u_(s) can be considered in order to optimize theperformance of the correlation process in term of resolution and signalto noise ratio in response to various considerations imposed by fieldapplications.

In some aspects of the present disclosure, coded acoustic signals in theprimary acoustic beam can also be used to enhance the amplitude andfocusing of the non-linear signal returning to the borehole, and toimprove signal detection sensitivity and signal to noise ratio. FIGS. 14a-14 d show an example of an application of the coded signal scheme to anoisy time series signal generated by numerical simulation. The noisytimes series signal simulates a signal returning to the borehole as aresult of non-linear interaction. White Gaussian noise with an amplitude10% larger than the amplitude of the non-linear interaction signal isadded to the time-series signal produced by the numerical simulation ofwave propagation in a non-linear model before the correlation with thecoding template is applied. The configuration is the same as that shownin FIGS. 12 a-12 d and FIGS. 13 a-13 d. FIG. 14( b) shows the simulatedreceiving signal containing noise recorded at 6 receivers of thereceiver array 1403. FIG. 14( d) shows the signal retrieved from thenoisy signals (in this case the simulated noisy signals) on the samereceivers when correlating with the coded template u_(s) (t) of 12pulses shown in FIG. 14( c). The coding scheme is thus shown toeffectively extract the signal from the non-linear interaction andminimize the noise, a useful characteristic for field applications.

The preceding text described how a combination of broadcast coding andsignal processing may be used to improve the detection and to determinethe amplitude of an acoustic wave signal generated by non-collinearmixing in a non-linear medium and to determine the acoustic travel timefrom sources to receiver array via the mixing zone and to infer themixing zone's non-linearity and Vp/Vs ratio. The following paragraphsdescribe a non-limiting implementation of the coding and signalprocessing method in the context of a borehole based measurement system.

Given an initial compressional and shear velocity model of theformations around the borehole, techniques such as ray tracing may beused to estimate the location of a mixing zone, 805 on FIG. 8,corresponding to chosen inclinations and azimuths (α₁, α₂, φ₁ and φ₂,809 to 812) and also the convergence and scattering angles (θ and ψ, 804and 806). This information is used to predict the time delay δ_(P) andfrequency ratio d_(P) required for the pulses from the two transmittersto arrive simultaneously at the mixing zone and generate a sequence ofscattered pulses by non-collinear interaction that arrive at a receiver,and to predict the total travel time T_(P) from the first acousticsource to a receiver via the mixing zone. Systematically scanning δ andd around their predicted values, and correlating the template u_(s)(t)with the recorded signal u₃(t) results in a suite of results M (t, δ, d)for each receiver element of the array 803. As discussed in previousparagraphs, the correlated signal M (t, δ, d) for each receiver elementcontains a band-limited spike corresponding to the non-linearinteraction in the mixing zone 805 if selection rules permit non-linearinteraction. A search is made in the space of (t, δ, d) on M(t, δ, d) toidentify the location (T_(NL), δ_(NL), d_(NL)) of the band-limited spikecorresponding to non-linear interaction at mixing zone 805, which shouldbe in the vicinity of (T_(P), δ_(P), d_(P)). Differences between(T_(NL), δ_(NL), d_(NL)) and (T_(P), δ_(P), d_(P)) are indications ofdeviation of the propagation velocity model from the true propagationcharacteristics of the rock formation. These differences are then usedto update the propagation velocity model by velocity tomographicinversion or other velocity updating methods. Given the relationshipsbetween frequency ratio d, Vp/Vs ratio, convergence angle and scatteringangle from equation 9 and FIG. 10, the Vp/Vs ratio of the rock formationat the mixing zone is then calculated from the observed value d_(NL),the convergence angle and the scattering angle at the mixing zone—thelatter two quantities can be calculated by raytracing or other numericalmethods from the updated propagation velocity model. The amplitude valueM (T_(NL), β_(NL), d_(NL)) contains information about the non-linearmixing strength of the rock formation at the mixing zone 805. It can beused for 3D-imaging of non-linear properties of the rock formation asdescribed in the discussion below.

The ability to process non-collinear acoustic mixing signals bycorrelation with a template signal to identify the combination ofparameters associated with a particular mixing zone, that is M (T_(NL),δ_(NL), d_(NL)), T_(NL), δ_(NL) and d_(NL), that can be subsequentlyused for the determination of Vp/Vs ratio, propagation model Vp and Vsand nonlinear properties is a direct consequence of the coding andcorrelating protocol. This unique characteristic underpins the imagingscheme that follows.

The discussion in the paragraphs below will focus on one non-limitingexample of the use of coded acoustic signals for creation of the 3Dimages of Vp/Vs ratio and non-linear properties of rock formationsurrounding the borehole. However, the use of coded acoustic signals hasbroader applications beyond those related to geology and petrophysicalapplications including the areas of non-destructive testing and medicalimaging.

By way of a non-limiting example, one measurement and data processingprotocol to enhance signal to noise ratio is discussed in the followingparagraphs for the system described in FIG. 8.

For the sake of simplicity, the operating protocol is described in thecontext of a non-attenuative rock formation. However, the followingmeasurement and data processing protocol can equally be applied to anattenuative rock formation. The effect of attenuation in the rockformation is to displace the origin of the scattered wave by apredictable amount related to the formation Q.

First, for a given ratio frequency ratio d of the two coded signals asdescribed in the above paragraphs, the coded primary acoustic beamsignals from first acoustic energy source 801 and second acoustic energysource 802 of the measurement system described in FIG. 8 are transmittedinto the earth. A time delay δ is maintained between two coded signalsof source 801 and source 802. The measurement geometry honors theselection rules, and the time delay is such that energy from the twosources arrives substantially simultaneously at the mixing zone. In oneembodiment, each component of the three component geophone at receiver803 at location z3 detects and records the returning acoustic waves.This measurement is denoted m(t, δ, d, z3). Alternatively or in additiona hydrophone may also be provided to detect a pressure signal in thereturning acoustic waves.

Second, the coded primary acoustic signals are transmitted from thefirst and the second acoustic energy sources as described in the aboveparagraphs but with polarity reversed, that is, with the phase shiftedby 180 degrees. The signal recorded at receiver 803 is denoted m (t, δ,d, z3).

Third, the two signals m(t,δ,d,z3) and m (t, δ, d, z3) are addedtogether to form the combined signal, which can be denoted as mm(t, δ,d, z3). Because the signals m(t, δ, d, z3) and m (t, δ, d, z3) haveopposite polarity, signals from linear interaction in the rock formationwill be cancelled out by the addition of m(t, δ, d, z3) and m (t, δ, d,z3). However, the non-linear responses of the earth will add coherentlysince the amplitude of the non-linear responses is proportional to theproduct of the amplitudes of the two primary signals and therefore willnot reverse polarity when the polarity of both primary signals isreversed. Therefore, mm(t,δ,d,z3) would essentially contain a signalfrom non-linear interaction of the rock formation.

Fourth, a time variant band-pass filter can be applied on the obtainedsignal mm(t,δ,d,z3), so as to keep a narrow band around the expectedbandwidth of the signal. The bandwidth of the obtained signal isdetermined from the frequency differences and bandwidths of the twoprimary broadcast signals.

Fifth, a cross-correlation of the filtered signal mm(t,δ,d,z3) with thetemplate coded signal is performed as described in the above paragraphsto obtain the pulsed signal which can be denoted as mmc(t, δ, d, z3).

Sixth, hodogram analysis can be applied to the three component dataobtained from the three uniaxial sensors of the receiver and/or appliedto the pressure signal detected by the hydrophone. These data may beused to analyze any of the possible modes P, SH and SV and can betransformed to obtain separate measurements of any SV, SH and Parrivals, denoted mmcr(t, δ, d, z3).

Seventh, the above six steps can be repeated multiple times withdifferent broadcast coded signals and the collection of mmcr(t,δ,d,z3)signals can be stacked to improve signal to noise. The resulting stackedsignal is the signal record M(t,δ,d,z3) for each of the SV, SH and Parrivals. For example, in a P+P to SV mode, the SV mode is detected bythe receiver while in a P+SV to P mode, the detected signal at thereceiver would be a P mode.

Eighth, the above seven steps can be repeated for a sweep through for asequence of many values δ and d to obtain the entire set of M(t, δ, d,z3). The described measurement and processing protocol allow for theconstruction of the measurement signals M (t, δ, d, z3) with high signalto noise ratio at the receiver arrays.

The measurements M (t, δ, d, z3) can be repeated for many transmitterlocations z1, z2 and many receiver array locations as the transmitterarrays and the receiver arrays can be moved independently. As theprimary acoustic beams from source 801 and 802 can be steeredindependently for any azimuth angles φ1, φ2 and elevation angles α1, α2,the measurements M(t,δ,d,z3) are also repeated for many angles φ1, φ2,α1 and α2. These repeated and multiple measurements may contain multipleredundant signals generated by non-linear interactions in the earth formany values of z1, z2, z3, φ1, φ2, α1 and α2. The redundancy allows foradditional signal to noise enhancements by signal processing oncomputers and for creation of 3D images of rock properties around theborehole.

It should be noted that the steps described above for the measurementand processing protocol can be re-ordered or eliminated in variouspermutations as warranted. Furthermore, there are many additional signalprocessing techniques familiar to those who are experienced with the artof seismic signal processing, e.g. multi-dimensional filtering, timemoveout analysis and stacking. These additional techniques can be addedto the measurement and data processing protocol described in the aboveparagraphs to improve the quality of the recorded data and processedimages. The correlated acoustic signal M(t, δ, d, z3) from non-linearinteractions has many properties rooted in the coding methodology andthe selection rules.

In the following paragraphs, an imaging method and workflow thatexploits these properties to construct 3D images of the non-linearproperties and Vp/Vs velocity ratio of an earth volume and determinesother rock properties such as Vp and Vs is discussed. A non limitingexample of the workflow is discussed below.

Referring to the measurement system described in FIG. 8 with travel timenotations denoted in FIGS. 12 a-12 d, and the discussion in the aboveparagraphs, the correlated signal record M (t, δ, d, z3) aftermeasurement and processing at a receiver location z3 for one particulartransmitter location and beam angle (z1, z2, φ1, φ2, α1 and α2) willcontain a band-limited spike at the travel time T=t1+t3 if the followingconditions are satisfied:

-   -   a) The transmitted beams intersect and interact non-linearly at        mixing zone 805.    -   b) The time difference δ is equal to the travel time difference        t1−t2.    -   c) The selection rules are obeyed, i.e., the frequency ratio d        used in the coding scheme obeys the condition of equation (9).

$\begin{matrix}{{\sin\left( {\theta/2} \right)} = {\left( {1 - d} \right)\frac{\sqrt{\left( {{Vp}/{Vs}} \right)^{2} - 1}}{2\sqrt{d}}}} & (19)\end{matrix}$

-   -   where Vp/Vs is the compressional to shear velocity ratio at the        mixing zone 805 and θ is the convergence angle between the first        and second transmitted beams. The Vp/Vs ratio and convergence        angle θ can be calculated by raytracing from the beam geometry,        location and beam direction parameters (z1, z2, z3, φ1, φ2, α1        and α2) and a model of compressional velocity Vp and shear        velocity Vs of the rock volume being investigated.

The above conditions dictate that the non-linear interaction at mixingzone 805 contributes to the record M (t, δ, d, z3) as a band-limitedspike signal at a single point in the (t, δ, d) space for each positionz3 of receiver 803. The observed location of the band-limited spikesignal on the record M (t, δ, d, z3) can be denoted as (T_(NL), δ_(NL),d_(NL), z3). The amplitude of this band-limited spike is a function ofthe non-linear interaction strength, β, at mixing zone 805.

A combining process (e.g., a stacking process) as commonly used in theseismic industry and borehole acoustic waveform analysis can beperformed on the signal records M (t, δ, d, z3). The progressive timedelay or “moveout” of the band-limited spikes on the signal records M(t, δ, d, z3) can be analyzed as a function of z3. For example, in astacking process, the signal records can be stacked to obtain a stackedrecord Ms(t, δ, d, z3 r) corresponding to a chosen reference location z3r. The reference location is selected such that the plurality of signalrecords M (t, δ, d, z3) can be stacked appropriately. This stackingprocess enhances the signal to noise ratio and improves thedetectability of the location (T_(NL), δ_(NL), d_(NL), z3 r) of theband-limited spike originating from the non-linear interaction on therecord M s(t, δ, d, z3 r). Although a stacking process is describedherein, other combination techniques can also be used.

Given an initial Vp and Vs velocity model, which can be estimated fromthe borehole well logs and assumptions about lateral continuity of therock formation properties away from the borehole, the trajectories andtravel times of acoustic beams with elevation angle α1 and azimuth angleφ1 from transmitter 801 at position z1 and elevation angle α2 andazimuth angle φ2 from transmitter 802 at position z2 can be calculatedby ray tracing or other numerical modeling techniques.

Therefore, the location of the mixing zone 805 can be located in spaceby ray tracing or other acoustic numerical modeling techniques from theparameters z1, z2, z3 r, φ1, φ2, α1 and α2 if the beams intersect. Thepredicted travel time t1 p, t2 p and t3 p between transmitter locations801 and 802, reference receiver z3 r and mixing zone 805 can also becalculated based on position and velocity using ray tracing or otheracoustic numerical modeling techniques.

The predicted pulse arrival time T_(p)=t1 p+t3 p and time differenceδ_(p)=t1 p−t2 p can be predicted from the compressional velocity Vp andshear velocity Vs model and then compared with the arrival time T_(NL)and difference time δ_(NL) of the observed band-limited spike on theactual record Ms(t, δ, d, z3 r). If the Vp and Vs velocity modelcorrectly approximates the true Vp and Vs velocity of the rockformation, the predicted times (T_(p), δ_(p)) are equal to observationtimes (T_(NL), δ_(NL)). If there are differences between the predictedtimes and the observed times, these differences can be used to updatethe propagating Vp and Vs velocity model to minimize the differences andachieve consistency between the modeled and observed data. Variousiterative velocity tomographic inversion methods that are familiar tothose experienced in the art of imaging in the seismic processingindustry can be used to update the propagating Vp and Vs model.

Given the Vp and Vs propagation model obtained through the abovetomographic velocity inversion step, the trajectories of acoustic beamswith elevation angle α1 and azimuth angle φ1 from transmitter 801 atposition z1 and elevation angle α2 and azimuth angle φ2 from transmitter802 at position z2 can be calculated by ray tracing or other numericalmodeling techniques For a given azimuth angle φ1, there will be anazimuth angle φ2 for which the source beams will intersect at a mixingzone 805 for which the location and convergence angle θ can becalculated by ray tracing or other numerical modeling techniques fromthe parameters z1, z2, z3 r, φ1, φ2, α1 and α2. The amplitude of thepulse at the point (T_(NL), δ_(NL), d_(NL)) on the record Ms(t, δ, d, z3r) can then be mapped to the spatial coordinates of the mixing zone 805.Since d_(NL) must obey Equation (19), the Vp/Vs velocity ratio at themixing zone 805 can be calculated from Equation (19) and mapped on toits spatial position. By repeating the above mapping step for a range ofvalues of parameters z1, z2, z3, φ1, φ2, α1 and α2, a 3D image of thenon-linear interaction strength β and a 3D image of velocity ratio Vp/Vscan be constructed. The velocity Vp/Vs ratio obtained from the abovemapping method using selection rules is an alternative method to usingthe ratio of the propagation velocity Vp and Vs obtained fromtomographic inversion of travel times.

The geometric mapping step discussed in the above paragraphs is only oneexample of many imaging techniques that can be used for 3D imaging fornon-linear property and Vp/Vs velocity ratio from the signal records M(t, δ, d, z3) for many values of parameters z1, z2, φ1, φ2, α1 and α2.Other advanced imaging techniques such as Kirchhoff imaging, beamimaging, wave equation imaging used in the seismic industry can beadapted for the 3D imaging of non-linear property and Vp/Vs velocityratio. For example, the three dimensional image of the propagationcompressional velocity Vp, the three dimensional image of thepropagation of shear velocity Vs, the three dimensional image of theratio of compressional velocity and shear velocity Vp/Vs, or the threedimensional image of non-linear properties of a rock formation, or anycombination of two or more thereof can be performed using Kirchhoffimaging, beam imaging or wave equation imaging. In addition, in oneembodiment, the value of propagation compressional velocity or value ofshear velocity or both can also be determined using tomographic velocityinversion or full wave form inversion or by iterative imaging incombination with tomographic velocity inversion or full wave forminversion.

As it can be appreciated, determining a value of a parameter can bedifferent from imaging the parameter. Indeed, an image of a parametermay only contain relative values of the parameter and does notnecessarily provide the information on the absolute value of theparameter. Therefore, obtaining an image of the velocity ratio Vp/Vs maybe different from determining the value of the velocity ratio Vp/Vs.Determining a value of the velocity ratio from the image of the velocityratio may require additional information.

For investigation of non-linear properties and the ratio ofcompressional to shear velocities farther into the rock formation from aborehole, sources of lower frequency, of order 500 Hz to 10 kHz, may beneeded since acoustic energy of lower frequency can penetrate fartherinto the rock formations before being attenuated to a non-detectablelevel. Lower frequency acoustic energy in the 500 Hz to 10 kHz frequencyrange has a wavelength much bigger than the borehole diameter. In thesecircumstances it is difficult to control the azimuth directions of theacoustic wave broadcast from sources deployed in the borehole. Theconfiguration shown in FIG. 8 with two primary beams of acoustic energyemanating from a borehole may not be suitable for probing and imaging ofnon-linear properties at large distance greater than hundreds of feetfrom the borehole. In view of this, a different low frequency (500 Hz to10 kHz) system and method is needed to maximize the distance ofinvestigation away from the borehole. The following paragraphs describea non-limiting example of such a system and method to generatethree-dimensional images of non-linear acoustic properties and Vp/Vsvelocity ratio using low frequency sources. Although the followingdescription will refer to the frequency range 500 Hz to 10 kHz, thesystem and method described can also be applicable and beneficial in ahigher frequency ranges, for example, 10 kHz to 500 kHz.

FIG. 15 a shows a system of two transmitters and a receiver or areceiver array that are arranged in the borehole to detect non-collinearmixing in a rock volume around the borehole. In one embodiment, theupper transmitter 1502 includes a linear array of transmitters which canbe clamped to or unclamped from the borehole. The lower transmitter 1501includes a linear array of transmitters which can also be clamped orunclamped. The receiver array 1508 includes a clamped three componentreceiver or a clamped three component receiver array. The transmittersand receivers can be moved together or independently. In one embodiment,array elements of transmitters 1501 and 1502 can be arranged, forexample using phase control, to broadcast acoustic energy into two cones(lower acoustic cone 1504 produced by transmitter 1501 and upperacoustic cone 1505 produced by transmitter 1502), with axes collinearwith transmitters 1501 and 1502. In a phase controlled system, the coneangles depend on the phase difference between transmitter elements andthe rock formation velocity. The intersection of the two conicalbroadcasts of acoustic energy is a toroidal shaped intersection volume1506. Where the selection rules are honored, scattered energy 1507 isgenerated by non-linear interaction around intersection volume center1506. The scattered energy originating from non-linear interaction isrecorded at the receiver or array of receivers 1508.

Because the vertical locations and the elevation angles of the conicalbroadcasts of the transmitters 1501 and 1502 are controllable, thespatial location (distance from the borehole and vertical location) oftheir toroidal intersection volume 1506 may be controlled and scannedover a three dimensional rock volume around the borehole 1500. To theextent that the convergence angles of the two cones and the frequencyratios of the two sources can be arranged to honor the selection rules,the scattered signals due to non-linear mixing at mixing zone 1506 thatare recorded at receiver 1508 contain information of the non-linearproperties of the formation at the intersection between the two cones.The data recorded by an array of three component geophones 1508 may beanalyzed to determine the azimuth and elevation to its origin. Thesignal coding methodology described in the above paragraphs and themeasurement and processing protocol described above can be applied tothe system depicted in FIG. 15( a). The correlated signal M (t, δ, d,z3) obtained from the latter system and configuration is composed of thelinear superposition of all the pulses generated by the non-linearinteraction at all intersection volume segments 1509-1, 2, 3, etc. to1509-k, that cover the entire circumference of the toroid intersectionvolume 1506 as shown in FIG. 15( b). As discussed in the aboveparagraphs, the contribution of the non-linear interaction of the waveby a segment 1509-k, corresponding to the interaction or mixing zone, tothe resulting correlated signal M (t, δ, d, z3) at a receiver atposition z3 in receiver array 1508 is a pulse with a travel time equalto the time of flight from transmitter 1501 to segment 1509-k and from1509-k to receiver if the following conditions are met:

-   -   a) the frequency ratio d, convergence angle θ and Vp/Vs velocity        ratio at the particular segment 1506-k obeys the selection rule        condition of equation (19),    -   b) the time delay δ between the coded source transmitters        signals is equal to the difference between the times of flight        from transmitter 1501 to 1509-k and from transmitter 1502 to        1509-k.

In other words, the pulses generated by non-linear mixing at theintersection volume segments 1509-1 to 1509-k in the correlated signal M(t, δ, d, z3) are distributed over a range of (t, δ, d) for eachreceiver at position z3. The contribution of each segment 1509-k can bemapped to a point in (t, δ, d) space in the correlated signal M(t, δ, d,z3). This property, together with the trajectory information of thesignal obtained from three component receivers allows for geometricmapping of the signal amplitude at the point (t, δ, d) in correlatedsignal M (t, δ, d, z3) to the spatial locations of the intersectionvolume segments 1509-1 to 1509-k within the toroid intersection volumeusing the imaging methods discussed in the above paragraphs. An initialVp and Vs propagation model is constructed. Ray tracing, travel timeanalysis and iterative tomographic velocity determination are thenperformed to obtain an updated Vp and Vs propagation model. Non-linearproperties and Vp/Vs velocity ratio in the segments 1509-1 to 1509-k inthe toroid intersection volume can then be extracted and mapped to thespatial locations on the toroidal intersection volume using ray tracinganalysis applied to the updated Vp and Vs model using the workflowdescribed in the above paragraphs. By repeating the measurements for allelevation angles of conical broadcast and vertical locations in theborehole of the transmitters, the images of non-linear properties andVp/Vs velocity ratio can be constructed for all mixing zones surroundingthe borehole. The images for all scanned mixing zones can then becombined to yield a complete 3D image of non-linear properties and Vp/Vsvelocity ratio using a suitable processing method known to those who areskilled in the art of seismic imaging such as, for example, the weightedstacking method, of all the images.

The system and method using low frequency conical acoustic broadcastsfor a vertical well can work well when the rock volume has no azimuthalsymmetry. However, if the rock volume has a very high degree ofazimuthal symmetry for the propagating velocities Vp and Vs andtherefore by implication their Vp/Vs velocity ratio, such a system mayencounter some difficulties in resolving the azimuthal variations information properties and generating 3D images. Referring to FIG. 15( b),the non-linear signals generated by non-linear interaction from segments1509-1 to 1509-K in the toroid intersection volume arrive simultaneouslyat each receiver when there is total azimuthal symmetry. In this case,it would be difficult to separate the pulses originating from multiplesegments 1509-1 to 1509-K in the toroidal intersection volume as theseoccur at the same time in the correlated signal M. This introducesambiguity into the mapping exercise. The above difficulty can be avoidedif a borehole or borehole system is designed to overcome the limitationsdue to the azimuthal symmetry. In the following paragraphs, anon-limiting measurement system and method utilizing various wellboreconfigurations designed to achieve this goal will be described.

FIGS. 16 a and 16 b show an example of non-collinear mixing arrangementwith receiver array 1603 located in a straight section of the boreholeand centers of transmitters 1601 and 1602 located on the receiverarray's extended axis 1625. For the case of linear phased arrays, thetransmitters broadcast acoustic energy in cones 1604 and 1605 with axesaligned with the transmitter arrays. The cones and their intersectionlocus 1607 are illustrated in FIGS. 16 a and 16 b, in accordance withaspects of the present disclosure. As shown in FIG. 16 a, theintersection locus may be considered as a series of adjacentintersection volume segments, 1608-k, where k=1 to K, four of which areidentified as 1608 a, 1608 b, 1608 c and 1608 d. From geometric analysisit can be demonstrated that if two intersection volume segments have thesame convergence angles, their corresponding time of flight differences(from lower and upper transmitter to intersection volume segment) t1−t2are different. Two locations on opposite sides of the intersection locuscorresponding to the mixing zones, with similar convergence angles andVp/Vs velocity ratio, may therefore be individually activated bycontrolling the frequency ratio d and the time delay δ between codedbroadcasts from the two transmitters. Similarly, two mixing zones withthe same time of flight difference t1−t2 have different convergenceangles θ, so that an acoustic signal arriving simultaneously at twomixing segments could only honor the selection rule requirements for aVp/Vs velocity ratio, frequency ratio d and convergence angle θ at oneof the two locations.

As it can be appreciated from the above paragraphs, the intersection oftwo conical acoustic broadcasts defines an intersection volume in a formof a toroid. For the purpose of the present disclosure, a toroid isdefined as an “annular” shape that is generated by revolving a planegeometrical shape such as a polygonal shape, circle, ellipse or othershape to define a closed volume. In one embodiment, the toroid can be aring torus or O-ring where the plane geometrical shape orcross-sectional shape is a circle that is revolved around an axis. Inanother embodiment, the toroid can be defined as a polygonal shape thatis revolved elliptically to form a closed volume. The toroid volume canbe segmented in to a plurality of intersection volume segments.Depending upon non-linear selection rules and a judicious selection ofvarious parameters including a start time difference and frequency ratiobetween the broadcast acoustic signals, one a more intersection volumesegments can be “activated” to provide one or more mixing zones wherethe two conical broadcast signals interact non-linearly within themixing zone(s) to generate a signal that is representative of thenon-linear properties of the rock formation in that zone.

The coding methods discussed in the above paragraphs, the measurementand processing protocols described in the above paragraphs and theimaging methods discussed in the above paragraphs can be applied to themeasurement system illustrated in FIGS. 16 a and 16 b. The applicationsfollow the general approach described in the above paragraphs. Unlikethe straight borehole configuration of FIG. 15, there is no issue ofsimultaneous arrivals in the space of (t, δ, d). Thus, measurementsystem described in FIG. 16 using a borehole with an intentionally benttrajectory would be more robust for general 3D imaging of non-linearproperties and Vp/Vs velocity ratio. A by-product of the imaging methodis the Vp and Vs propagation model generated by tomographic velocityinversion of the intermediate step of the imaging process.

It should be noted that the absence of azimuthal symmetry in theconfiguration of the curved or angled borehole trajectory and tiltedconical acoustic wave broadcast as shown on FIG. 16 can also be achievedon a smaller scale by offsetting the axes of smaller transmitter arrayswithin a straight borehole, or by a similar configuration on a wirelineor pipe conveyed logging tool, etc.

FIGS. 17 a and 17 b show two additional examples of transmitter-receiverarrangements within various boreholes configurations of axialorientation and cone angle that can be used for the creation of the 3Dimages of Vp/Vs velocity ratio and non-linear properties of rockformation surrounding the borehole. FIG. 17 a shows an example singlewell arrangement with a cranked rat hole where there is a completeintersection of lower cone within the upper cone. For example, as shownin FIG. 17 a, upper transmitter 1702 is arranged to produce a wider coneof acoustic energy 1705 than the narrower cone 1704 produced by lowertransmitter 1701, such that there is a complete intersection of thelower cone within the upper cone. Both transmitters 1701 and 1702 arepositioned in rat hole 1706, while receiver 1703 is positioned in mainvertical borehole 1700. As in the configurations of FIGS. 15 and 16 a-16d, transmitters 1701 and 1702 can be arranged as an array, for example alinear array, of acoustic point sources in a borehole. Acoustic energygenerated by transmitters 1701 and 1702 interacts in the non-linearmaterial in the intersection zone and acoustic energy is received atreceiver 1703 in accordance with the selection rules, as discussedabove. The non-linear mixing zone includes an intersection locus 1709between cones 1704 and 1705 spanning a closest point 1707 to theborehole 1700 and a farthest point 1708 from the borehole 1700.

FIG. 17 b shows another example of single well arrangement with a moreseverely cranked rat hole with a lower transmitter emitting energy nearperpendicular to the axis of borehole 1700. In these configurations, theintersection between the cones is a hyperbola, not an ellipse as in theabove examples. Nonetheless, similar measurements, coding, dataprocessing and imaging protocols remain applicable. In addition, becausethe intersection between the cones is not a closed curve, depth ofinvestigation is determined by source strength, receiver sensitivity,and the effectiveness of the signal processing algorithms.

One difference between a configuration resulting in a closed ellipticalintersection locus with a configuration resulting in a parabolic opencurve locus is that in a closed elliptical intersection locus afrequency ratio scan may start at a low frequency ratio f2/f1 (see, forexample, FIG. 10 b) that corresponds to a convergence angle higher thanthat at the nearest point. The frequency ratio f2/f1 can then beincreased, for example, until the nearest point on the ellipse isactivated. The scan can be continued until the farthest intersectionpoint is reached. By increasing further frequency ratio f2/f1 no signalwould be received as no zone is activated. On the other hand, if theintersection is an open curve, the frequency ratio f2/f1 can be scannedstarting at the nearest point and continue until the returning signalsto the receiver from either side of the hyperbola become undetectable.

FIG. 18 a shows an example of a vertical well and sidetrack withreceivers in the vertical part of the well. FIG. 18 b shows anotherexample of a vertical pilot hole and horizontal sidetrack with receiversin the sidetrack in accordance with aspects of the present disclosure.The main vertical borehole 1800 includes transmitter 1801 arranged toproduce a vertical cone of acoustic energy 1804, while sidetrackborehole 1806 includes transmitter 1802 arranged to produce acousticcone 1805. Receiver 1803 can be arranged in either main verticalborehole 1800 as in FIG. 18 a, sidetrack borehole 1806 or both mainborehole 1800 and sidetrack borehole 1806 depending on the particularapplication used. As in the examples of FIGS. 17 a to 17 c, transmitters1801 and 1802 and receiver 1803 can include an array of transmitters andreceivers, respectively. Transmitter 1802 in sidetrack borehole 1806 canbe located above or below transmitter 1801 in main vertical borehole1800.

Although the configurations of FIGS. 17 a to and 17 b, 18 a and 18 bdiffer somewhat in complexity from the drilling and operationperspectives, there are many benefits to using different configurationsincluding the ability to perform deeper remote sensing from the boreholeby maximizing the distance to the intersection of the two cones.Moreover, transmitters generating acoustic energy in a direction nearperpendicular to the borehole can provide more power and more angularresolution for the scans defined by smaller cone angles. It should benoted that the above Figures are only example configurations of the useof a multitude of possible borehole configurations. As it can beappreciated, there are many other borehole configurations that alsoallow for the placement of the two primary acoustic arrays at differentazimuth angles and elevation angles.

The techniques described above, a combination of invoking the selectionrules and signal coding, may be used to scan and image a volume definedby two intersecting cones formed by the acoustic energy from the twotransmitters, some distance away from the borehole. The discussion abovedescribed the P+P

SV interaction. However, other permitted interactions can also be usedin a similar fashion with examples shown in Table 1.

As can be appreciated from the above paragraphs, various methods ofinvestigating a rock formation can be implemented with a system forsurvey planning, data acquisition and storage, and image processing andinterpretation. FIG. 19 depicts a system for survey planning, dataacquisition and storage, and image processing and interpretation,according to an embodiment of the present invention. In one embodiment,the system can generate 3D images of non-linearity properties, Vp/Vsvelocity ratio and propagation compression and shear velocity of acylindrical volume of rock formation, centered on the wellbore. In oneembodiment, the 3D images of non-linearity and Vp/Vs velocity ratio caninclude images of non-linearity and Vp/Vs velocity ratio extending outto a radius of investigation of several hundred meters, for example.

In one embodiment, the system may be considered as a suite of hardwareand/or software or module sub-systems. Sub-systems 1900 to 1904 are usedfor survey planning and execution, downhole tool conveyance, coding andbroadcast of the transmitted acoustic waves, and recording and detectionof the non-linear signal. Sub-systems 1901 and 1905 are used forpost-survey image processing. Sub-system 1900 is used for survey design,data design acquisition, control and recording. Sub-system 1901 is usedfor preliminary non-linearity and velocity imaging. Sub-system 1902 isused for receiver and sensor control and transmission. Sub-system 1902is configured to emit controlled acoustic broadcasts and receiveacoustic energy. Sub-system 1903 is used for generating a broadcastsignal. Sub-system 1904 is used for non-linear signal detection.Sub-system 1905 is used for imaging non-linearity and imaging velocity.

In one embodiment, sub-system 1900 includes modeling for acquisitionmodule 1907, data acquisition controller 1908, data pre-processing andenhancement module 1930 and data storage device 1921. In one embodiment,sub-system 1901 includes initial velocity model module 1906 and module1931 for preliminary generation of three dimensional images includingpropagation compressional and shear velocity images, Vp/Vs velocityratio images and images of non-linearity which are associated withamplitudes of the measured signal originating from the non-linearinteraction at the mixing zone. In one embodiment, sub-system 1902includes tool deployment and transport module 1909, tool mechanicalcontroller 1910, azimuth and elevation controller 1917 for controllingthe azimuth and elevation angles of the first acoustic source (S1), andazimuth and elevation controller 1918 for controlling the azimuth andelevation angles of the second acoustic source (S2). In one embodiment,sub-system 1903 includes coded signal generator 1911, frequencymultiplier and time delay module 1912, signal amplifier 1913 forgenerating the signal sent to first acoustic source (S1), signalamplifier 1914 for generating the signal sent to second acoustic source(S2). In one embodiment, sub-system 1904 includes receiver module(s)1922 for receiving signals u3(t) from receivers R1, R2, . . . , Rn,non-linear signal enhancement module(s) 1924 for enhancing the signalreceived by the signal receiver module(s) 1922, a template signalgenerator module 1927 for generating a template signal u_(s)(t), and asignal correlation module 1928 for correlating the received signal u₃(t)with the template signal u_(s)(t), as described in the above paragraphs.In one embodiment, sub-system 1905 includes data pre-processing andenhancement module 1932, velocity model iteration module 1933, imagingiteration module 1934, output image module 1936 for velocity ratioimages and/or non-linearity images, and output velocity module 1935 foroutputting determined values of velocities Vp, velocity Vs and/or Vp/Vsvelocity ratio.

As it can be appreciated, the term module is used herein to encompass ahardware device, a software program, or both. For example, imageiteration module can be a piece of hardware that is configured toperform the iteration or a software program that can be run on acomputer to perform the iteration, or includes both a piece of hardwareand software application.

In operation, prior to data acquisition, logs of compressional and shearslowness and information about formation lateral continuity can be usedto build an initial layered earth model extending laterally away fromthe well bore using module 1906. The initial velocity model from module1906 is used by a forward modeling acquisition module 1907 to provide aplan for data acquisition that an operator uses to program dataacquisition controller 1908 using operator inputs.

After sub-system 1902 is deployed into the borehole via tool deploymentand transport module 1909 and clamped via tool mechanical controller1910 to the borehole wall if needed, input commands can be sent to thecoded signal generator sub-system 1903 where coded pulse sequences aregenerated by coded signal generator module 1911. The coded signalsgenerated by the coded signal generator module 1911 are adjusted infrequency and delayed by the frequency multiplier and time delay module1912 such that the signal amplifiers 1913 and 1914 provide signals totransmitters or sources S1 1915 and S2 1916 to broadcast the signals ina delayed fashion so that the signals from S1 and S2 arrivesimultaneously at the mixing zone, as depicted, for example, on FIG. 12a.

The geometry of the broadcasts including the elevation and azimuthangles of the acoustic broadcasts from sources S1 1915 and S2 1916 iscontrolled by commands from the data acquisition controller 1908 whichsends angle control commands to downhole azimuth and elevation anglecontrollers 1917 and 1918. All data pertaining to tool configuration andbroadcast geometry collected from tool deployment 1909, tool mechanicalcontroller 1910, azimuth and elevation controllers 1917 and 1918indicated herein as record acquisition parameters 1919 are recorded datastorage device 1921. Similarly, the coding scheme from coded signalgenerator sub-system 1903 indicated herein as record broadcastinformation at 1920 is also recorded at data storage device 1921.

In one embodiment, signals from signal modules 1922 recorded at thereceiver or receivers 1923 (e.g., each of the receivers may have forexample hydrophones, 3 component geophones or both R1 to Rn) can beprocessed by non-linear signal enhancement module 1924 to enhance thecontent of non-linear origin and reduce or substantially suppresssignals of linear interaction origin or potential noise. Raw signalsindicated at 1925 from signal receive modules 1922 and enhanced signalsindicated at 1926 are stored in data storage device 1921. A templatesignal u_(s)(t) generated by template signal generator 1927, which canbe derived from signals u₁(t) and u₂(t) generated by signal generators1912 and frequency multiplier and time delay module 1912, is correlatedwith received signals indicated by 1925 at 1928, as described forexample in FIGS. 12 to 14. The correlation of template signal u_(s)(t)and received or detected signal u₃(t) is used to extract via correlatedsignal output module 1929 a correlated signal M(t, d, δ, z3). Thecorrelated signal is also stored in data storage device 1921.

In one embodiment, the data acquisition process implemented usingcomponents or modules 1909 to 1929 may be repeated with different beamgeometry or at a multiple locations (z3) within the well. In oneembodiment, data already recorded may be used to guide changes inacquisition parameters. For example, stored data within storage device1921 may be further enhanced, for example, by hodogram analysis withinpreprocessing and hodogram processing module 1930. The data stored instorage device 1921 can be further used in conjunction with initialvelocity model from initial velocity model module 1906 to create a setof images of non-linear properties and/or Vp/Vs ratios with imagingmodule 1931. These may be used to refine modeling by acquisition designmodule 1907 and/or acquisition parameters controlled by data acquisitioncontroller 1908.

After the survey is complete, further data processing may be implementedvia data pre-processing and enhancement module 1932. In one embodiment,hodogram analysis can be conducted to pre-condition the data for finalanalysis. The initial velocity model in module 1906 and images frommodule 1931 can be used as a starting point for further iteration of thevelocity model through velocity model iteration module 1933 and imagingiteration of non-linear properties and/or Vp/Vs ratio through imagingiteration between velocity modeling module 1933 and imaging module 1934.The final result of the iteration is an optimized velocity model outputthrough output module 1935 and images including Vp/Vs ratio imagesand/or non-linear properties images output through output module 1936.

In one embodiment, the above implementation of the system is suitablefor imaging out to relatively large distances from the wellbore (forexample out to several hundred meters) and includes components designedto maximize signal to noise ratio and the detection of tenuous signalsfrom a complex petrophysical, stratigraphic and structural context. Nearwellbore applications probing a smaller volume with less variation inproperties and stronger returned signals could potentially dispense withsome aspects or portions or modules of the system concerned with signaldetection and velocity model iteration. Likewise, in a less demandingacquisition environment, some aspects of the hardware could besimplified, for example clamped three-component geophones could bereplaced with non-directional hydrophone receivers mounted on acentralized sonde.

Furthermore, as it can be appreciated, although the system is describedabove as linking the acquisition data portion of the system to theimaging portion of the system, the acquisition of data portion can beaccomplished separately from the imaging of Vp/Vs ratio and/ornon-linear properties. Indeed, the acquired data can be accomplished bya first entity and the data stored in data storage device 1921. Theacquired data in data storage device 1921 can then be transferred to asecond entity, which can be the same or different from the first entity,the second entity can employ the imaging sub-system or imaging methoddescribed in the above paragraphs to obtain the Vp/Vs and/or non-linearproperties images.

Furthermore, although each module is described in the above paragraphsas having a specific functionality, as it can be appreciated anyfunctionality in one or more modules can be moved to any other one ormore modules. For example, some or all functionality in the coded signalgenerator sub-system 1903 can be moved to the non-linear signaldetection subsystem 1904.

In addition, it must be appreciated that the term processor is usedherein to encompass one or more processors. The one or more processorscan be configured to implement the methods or portions of the methodsdescribed herein. The one or more processors can be located in one ormore computers such as, for example, in a distributed computingenvironment. In some embodiments, programs for performing methods inaccordance with embodiments of the invention can be embodied as programproducts in a computer such as a personal computer or server or in adistributed computing environment comprising a plurality of computers.Where reference is made to a processor that term should be understood toencompass any of these computing arrangements. The computer may include,for example, a desktop computer, a laptop computer, a handheld computingdevice. The computer program products may include a computer readablemedium or storage medium or media having instructions stored thereonused to program a computer to perform the methods described above.Examples of suitable storage medium or media include any type of diskincluding floppy disks, optical disks, DVDs, CD ROMs, magnetic opticaldisks, RAMs, EPROMs, EEPROMs, magnetic or optical cards, hard disk,flash card (e.g., a USB flash card), PCMCIA memory card, smart card, orother media. Alternatively, a portion or the whole computer programproduct can be downloaded from a remote computer or server via a networksuch as the internet, an ATM network, a wide area network (WAN) or alocal area network.

Although the invention has been described in detail for the purpose ofillustration based on what is currently considered to be the mostpractical and preferred embodiments, it is to be understood that suchdetail is solely for that purpose and that the invention is not limitedto the disclosed embodiments, but, on the contrary, is intended to covermodifications and equivalent arrangements that are within the spirit andscope of the appended claims. As a further example, it is to beunderstood that the present invention contemplates that, to the extentpossible, one or more features of any embodiment can be combined withone or more features of any other embodiment.

What is claimed is:
 1. A system for investigating non-linear propertiesof a rock formation around a borehole, comprising: a first sub-systemconfigured to perform data acquisition, control and recording of data; asecond subsystem in communication with the first sub-system andconfigured to perform non-linearity and velocity preliminary imaging; athird subsystem in communication with the first subsystem and configuredto emit controlled acoustic broadcasts and receive acoustic energy; afourth subsystem in communication with the first subsystem and the thirdsubsystem and configured to generate a source signal directed towardsthe rock formation; and a fifth subsystem in communication with thethird subsystem and the fourth subsystem and configured to performdetection of signals representative of the non-linear properties of therock formation, the fifth subsystem comprising a template signalgenerator module configured to generate a template signal designedaccording to forecast properties of the signals to be detected.
 2. Thesystem according to claim 1, wherein the first subsystem comprises anacquisition modeling module configured to receive inputs from the secondsubsystem and operator inputs.
 3. The system according to claim 2,wherein the first subsystem comprises a data acquisition controllerconfigured to receive operator inputs and inputs from an acquisitiondesign module.
 4. The system according to claim 3, wherein the firstsubsystem comprises a data pre-processing and enhancement module and adata storage device, the data pre-processing and enhancement moduleconfigured to read data from the data storage device and input data intothe second subsystem.
 5. The system according to claim 1, wherein thesecond subsystem comprises an initial velocity model module configuredto provide an initial velocity model derived from logs of compressionaland shear slowness and information about formation lateral continuity tothe first subsystem.
 6. The system according to claim 5, wherein thesecond subsystem comprises an image initializing module configured toinitialize volumes of propagation compressional and shear velocityvalues, velocity ratio images and images of non-linearity which areassociated with amplitudes of a measured signal generated by thenon-linear interaction at a mixing zone.
 7. The system according toclaim 1, wherein the third subsystem comprises a first acoustic source,a second acoustic source, one or more receivers, a tool deployment andtransport module, a tool mechanical controller, a directional controllerfor controlling an orientation of the first acoustic signal, and adirectional controller for controlling an orientation of the secondacoustic signal.
 8. The system according to claim 7, wherein the thirdsystem is configured to receive from the first subsystem commands tocontrol the directional controllers within the third subsystem tocontrol azimuth and elevation angles of the first acoustic signal, thesecond acoustic signal, or both.
 9. The system according to claim 7,wherein acquisition record parameters pertaining to tool configurationand broadcast geometry are collected from the third subsystem and arerecorded in a data storage device within the first subsystem.
 10. Thesystem according to claim 1, wherein the fourth subsystem comprises asignal generator configured to generate a first signal, a signalgenerator configured to generate a second acoustic signal, a frequencymultiplier and start time difference module, and a coded signalgenerator.
 11. The system according to claim 10, wherein the fourthsubsystem is configured to receive input commands from the firstsubsystem.
 12. The system according to claim 11, wherein the fourthsubsystem is configured to receive input commands from the firstsubsystem so as to generate pulse sequences using the coded signalgenerator module.
 13. The system according to claim 12, wherein thecoded signal generated by the coded signal generator module is inputinto a first signal control and amplifier module to input a first signalat a first frequency to the first acoustic source, wherein the codedsignal generated by the coded signal generator module is input intofrequency multiplier and start time difference module and then inputinto a second signal control and amplifier module to provide a secondsignal to the second acoustic source having a start time differencerelative to the first signal and having a second frequency which is aselected fraction of the first frequency.
 14. The system according toclaim 13, wherein the start time difference and the frequency fractionand are stored as record broadcast information in a data storage devicewithin the first sub-system.
 15. The system according to claim 1,wherein the fifth subsystem comprises a receiver module configured toreceive a signal from one or more receivers, a non-linear signalenhancement module configured to enhance the signal received by thesignal receiver module, and a signal correlation module configured tocorrelate the received signal with the template signal.
 16. The systemaccording to claim 15, wherein signals from the receiver module areprocessed by the non-linear signal enhancement module to enhance acontent of non-linear origin and reduce noise, wherein the signals fromthe receiver module and enhanced signals are stored in a data storagedevice within the first sub-system.
 17. The system according to claim15, wherein the correlation module is configured to correlate thetemplate signal with the received signal so as to extract a correlatedsignal, the correlated signal identifying a signal generated at anintersection of a first signal from a first acoustic source and a secondsignal from a second acoustic in a non-linear mixing zone within therock formation around the borehole.
 18. The system according to claim17, wherein the correlated signal is stored in a data storage devicewithin the first subsystem.
 19. The system according to claim 18,wherein a data acquisition controller within the first subsystem isconfigured to repeat recording within the storage device of the firstsubsystem and repeat extracting the correlated data from a plurality ofvalues of the position of the first acoustic source, the position of thesecond acoustic source, the position of the receiver, an elevation angleof the first acoustic signal, or an elevation angle of the secondacoustic signal, or any combination of two or more thereof.
 20. Thesystem according to claim 19, further comprising a hodogram analysismodule configured to process stored data within the storage device tofurther enhance the correlated data.
 21. The system according to claim1, further comprising a sixth subsystem in communication with the secondsubsystem and configured to perform imaging of non-linear properties ofthe rock formation and determining acoustic signal velocity within therock formation.
 22. The system according to claim 21, wherein the sixthsubsystem comprises sub-system a data pre-processing and enhancementmodule, a velocity model iteration module, an imaging iteration module,an output image module for velocity ratio images and/or non-linearityimages, and an output velocity module for outputting determined valuesof compressional velocity Vp, shear velocity Vs, or velocity ratiobetween the compressional velocity and the shear velocity, or anycombination of two or more thereof.
 23. The system according to claim17, wherein the correlated signal is a function of signal time t,frequency ratio d of a first frequency of the first signal and a secondfrequency of the second signal, and a time delay δ between the firstsignal and the second signal.
 24. The system according to claim 1,wherein the fifth subsystem further comprises a signal correlationmodule configured to correlate detected signals with the template signalto extract a correlated signal representative of an acoustic signalgenerated by a nonlinear interaction of the controlled acousticbroadcasts in a non-linear mixing zone within the rock formation aroundthe borehole.